Power plant with co2 capture

ABSTRACT

A method is provided for operating a combined cycle power plant having at least one gas turbine, a heat recovery steam generator (HSRG), a steam turbine and a CO2 capture system. The method includes recirculating a first partial flow of flue gases from the HRSG. The method also includes capturing CO2 from a second partial flow of flue gases from the HRSG; and operating a supplementary firing to increase the net power output of the plant and to at least partly compensate the power consumption of the CO2 capture system. A combined cycle power plant is also provided. The plant includes at least one gas turbine, at least one heat recovery steam generator, at least one steam turbine at least one CO 2  capture system, and flue gas recirculation. The plant also includes a low excess air supplementary firing.

INCORPORATION BY REFERENCE

The following documents are incorporated herein by reference as if fullyset forth: U.S. patent application Ser. No. 13/157,897, filed Jun. 10,2011; International Application No. PCT/EP2009/067674 filed Dec. 21,2009; and European Patent Application No. 08172880.0, filed Dec. 24,2008.

FIELD OF INVENTION

The invention relates to combined cycle power plants with integrated CO₂capture and supplementary firing as well as to their operation.

BACKGROUND

In recent years it has become obvious that the generation of greenhousegases leads to global warming and that further increase in greenhousegas production will accelerate global warming. Since CO₂ (carbondioxide) is identified as a main greenhouse gas, CCS (carbon capture andstorage) is considered as one of the potential major means to reduce therelease of greenhouse gases into the atmosphere and to control globalwarming. In this context CCS is defined as the process of CO₂ capture,compression, transport and storage. Capture is defined as a process, inwhich CO₂ is removed either from the flue gases after combustion of acarbon based fuel or the removal of and processing of carbon beforecombustion. Regeneration of any absorbents, adsorbents or other means toremove CO₂ from a flue gas or fuel gas flow is considered to be part ofthe capture process.

Backend CO₂ capture, also called post-combustion capture, is acommercially promising technology for fossil fueled power plantsincluding CCPP (combined cycle power plants). In post-combustion capturethe CO₂ is removed from a flue gas. The remaining flue gas is releasedto the atmosphere and the CO₂ is compressed for transportation, andstorage. There are several technologies known to remove CO₂ from a fluegas such as absorption, adsorption, membrane separation, and cryogenicseparation. Power plants with post combustion capture are the subject ofthis invention.

All known technologies for CO₂ capture require relatively large amountsof energy. Due to the relatively low CO₂ concentration of only about 4%in the flue gases of a conventional CCPP, the CO₂ capture system (alsocalled CO₂ capture plant or CO₂ capture equipment) for a conventionalCCPP will be more costly and energy consuming per kg of captured CO₂than one for other types of power plants, which have flue gas flows athigher CO₂ concentrations.

The CO₂ concentration in the CCPP flue gas depends on the fuelcomposition, the gas turbine type and load and may vary substantiallydepending on the operating conditions of the gas turbine. This variationin CO₂ concentration can be detrimental to the performance, efficiency,and operatability of the CO₂ capture system.

To increase the CO₂ concentration in the flue gases of a CCPP two mainconcepts are known. One is the recirculation of flue gases as forexample described by O. Bolland and S. Saether in “NEW CONCEPTS FORNATURAL GAS FIRED POWER PLANTS WHICH SIMPLIFY THE RECOVERY OF CARBONDIOXIDE” (Energy Convers. Mgmt Vol. 33, No. 5-8, pp. 467-475, 1992)).Another one is the so called tandem arrangement of plants, where theflue gas of a first CCPP is cooled down and used as inlet gas for asecond CCPP to obtain a flue gas with increased CO₂ concentration in theflue gas of the second CCPP. Such an arrangement is for exampledescribed in US20080060346. These methods reduce the total flue gasflow, increase the CO₂ concentration, and thereby reduce the requiredflow capacity of absorber and power consumption of the capture system.

These methods, as well as many further published methods for theoptimization of the different process steps, and the reduction of thepower and efficiency penalties by integrating these processes into apower plant, aim to reduce the capital expenditure and the powerrequirements of CO₂ capture system.

SUMMARY

The present disclosure is directed to a method for operating a combinedcycle power plant having at least one gas turbine, a heat recovery steamgenerator (HSRG), a steam turbine and a CO₂ capture system. The methodincludes recirculating a first partial flow of flue gases from the HRSG.The method also includes capturing CO₂ from a second partial flow offlue gases from the HRSG; and operating a supplementary firing toincrease the net power output of the plant and to at least partlycompensate the power consumption of the CO₂ capture system.

In another aspect, the present disclosure is directed to a combinedcycle power plant. The plant includes at least one gas turbine, at leastone heat recovery steam generator, at least one steam turbine at leastone CO₂ capture system, and flue gas recirculation. The plant alsoincludes a low excess air supplementary firing.

BRIEF DESCRIPTION OF THE DRAWINGS

The invention, its nature as well as its advantages, shall be describedin more detail below with the aid of the accompanying drawings.Referring to the drawings.

FIG. 1 schematically shows a CCPP with backend CO₂ absorption includingflue gas recirculation and low excess air ratio supplementary firing.

FIG. 2 schematically shows a low excess air ratio supplementary firingburner for application in a HRSG of a CCPP with flue gas recirculation.

FIG. 3 schematically shows the normalized residual oxygen concentrationof the gas turbine flue gas GT_(O2) required for supplementary firing asa function of the relative load of the supplementary firing SF_(load)without additional ambient air or oxygen supply.

FIG. 4 schematically shows the normalized residual oxygen concentrationof the gas turbine flue gas GT_(O2) required for supplementary firing asa function of relative load of the supplementary firing SF_(load) withadditional ambient air or oxygen supply F_(air) and the residual oxygenconcentration after supplementary firing SF_(O2).

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS Introduction to theEmbodiments

An objective of the present invention is to provide a combined cyclepower plant (CCPP) comprising at least one gas turbine, one heatrecovery steam generator (HRSG), one steam turbine, and carbon dioxide(CO₂) capture system with enhanced operational flexibility, and toreduce capacity penalties for CO₂ capture as well as an operating methodfor such a CCPP.

In particular the impact of CO₂ capture on the capacity of a CCPP is tobe minimized, i.e. the electric power delivered to the power grid by theplant including the CO₂ capture system is to be maximized.

To this end an operating method for a CCPP with flue gas recirculation,CO₂ capture and supplementary firing is proposed as well as a plant tocarry out such a method. The essence of the invention is an operatingmethod for a CCPP with flue gas recirculation, which allows operation ofa supplementary firing burner in flue gases of a CCPP with flue gasrecirculation, which at least partially compensates for the powerrequirements of the CO₂ capture system. The supplementary firing burnercan be installed in the HRSG of the CCPP or as a duct firing in the flueduct from the gas turbine to the HRSG.

For flue gas recirculation, the flue gas flow of a gas turbine is splitinto at least two partial flows downstream of the HRSG. A first partialflow is returned to the inlet of the gas turbine via a flue gasrecirculation line, and a second partial flow is directed via the CO₂capture system to the stack for release to the environment. Further, abypass around the CO₂ capture system for direct release of flue gases tothe environment can be provided to increase the operational flexibility.This allows any combination of recirculation rate, of flue gas flow toCO₂ capture unit, and direct flue gas flow to the stack without CO₂capture.

Flue gas recirculation is applied to minimize the CO₂ capture system'ssize, its costs, and its power requirements. For optimized CO₂ capturethe flue gas recirculation rate should be maximized. The recirculationrate is defined as the ratio of flue gas mass flow from the gas turbine,which is recirculated to the compressor inlet, to the total flue gasmass flow of the gas turbine.

For high CO₂ capture efficiency and to minimize the flue gas mass flow,the oxygen concentration in the flue gas would ideally be 0%. Due tocooling air, which bypasses the gas turbine's combustion chamber, andexcess oxygen needed to assure complete combustion, recirculation islimited and some residual oxygen remains in the exhaust gas even withrecirculation. Typical recirculation rates determined by the operationalrequirements of the gas turbine are in the order of 30% to 50% for baseload operation.

Conventional supplementary firing burners are designed for residualoxygen concentration of 10% or more in the flue gas. The residual oxygenconcentration after a gas turbine with flue gas recirculation istypically lower than 10% and is not sufficient for conventionalsupplementary firing burner. In order to enable operation under theboundary conditions of flue gases from a gas turbine with flue gasrecirculation, the use of a low excess air supplementary firing burneris proposed. In this context a low excess air supplementary firingburner is a burner, which can be operated in a gas flow with less than10% oxygen concentration with a low stoichiometric ratio. Thestoichiometric ratio for this kind of a low excess air supplementaryfiring burner should be below 2, preferably below 1.5 or even below 1.2.Ideally this kind of burner can operate with a stoichiometric ratio asclose as possible to 1.

A conventional duct burner or an interstage burner could be used withadditional air supply at a high excess air ratio. However, this woulddilute the CO₂ concentration in the flue gas and increase the flue gasflow. It is therefore not an adequate solution for this application.

Instead of using CO₂ concentration or oxygen concentration the CO₂content, respectively the oxygen content can also be used in the contextof this invention.

In one embodiment, the recirculation rate can be controlled by at leastone control body. This can for example be a controllable damper or afixed splitter with a control body like a flap or valve in one or bothof the flue gas lines downstream of the splitter.

This allows for example to control the recirculation rate to the highestpossible rate under the conditions, that stable complete combustion inthe gas turbine can be maintained, and that the residual oxygenconcentration after the gas turbine is sufficient to maintain stablecomplete combustion of the supplementary firing.

Stable complete combustion in this context means, that CO and unburnedhydrocarbon emissions stay below the required level, which is in theorder of ppm or single digit ppms and that the combustion pulsationsstay within the normal design values. Emission levels are typicallyprescribed by guarantee values. Design values for pulsation depend onthe gas turbine, operating point, and combustor design, as well as onthe pulsation frequency. They should remain well below 10% of thecombustor pressure. Typically they stay below 1 or 2% of the combustorpressure.

The recirculation rate can for example also be used to control theoxygen concentration of the compressor inlet gases after mixing ambientair with the recirculation flow. The target oxygen concentration of theinlet gasses can for example be a fixed value, which is sufficient toassure stable, complete combustion in the gas turbine under alloperating conditions.

In a further embodiment, the target oxygen concentration of the fluegases is a function of relative load of the supplementary firing. It canbe minimized according to the requirements of the gas turbine as long asthe supplementary firing is switched off. Once supplementary firing isswitched on, the requirements of the gas turbine and of thesupplementary firing have to be considered. The larger one of the tworequirements determines the target residual oxygen concentration of theflue gas. The required residual oxygen concentration for thesupplementary firing itself can be a fixed value or a function of theburner load of the supplementary firing.

Further, in order to assure complete stable combustion of thesupplementary firing, introduction of additional air, and/or oxygenenriched air, and/or oxygen into the burner or upstream of the burner ofthe supplementary firing is proposed.

In a further embodiment the recirculation rate can be a fixed rate ordetermined independently of the supplementary firing. In order to assurecomplete stable combustion of the supplementary firing under theseconditions, the additional airflow, and/or oxygen enriched airflow,and/or oxygen flow is controlled.

The additional airflow, and/or oxygen enriched airflow, and/or oxygenflow can be a fixed flow. However, excess air or oxygen should beavoided in the flue gases in order to keep the efficiency of the CO₂capture high. Therefore a control of the additional air, and/or oxygenenriched air, and/or oxygen flow is proposed.

In one embodiment the additional airflow, and/or oxygen enrichedairflow, and/or oxygen flow is controlled as a function of the flue gasrecirculation rate.

In another embodiment the additional airflow, and/or oxygen enrichedairflow, and/or oxygen flow is controlled as a function of residualoxygen concentration of the flue gases of the gas turbine.

In a further embodiment the additional airflow, and/or oxygen enrichedairflow, and/or oxygen flow is controlled as a function of the relativeload of the supplementary firing.

Further parameters, such as the flue gas temperatures before and afterthe supplementary firing, the flue gas flow velocity etc. can be used.

A combination of the above control parameters and targets is possible.For example good operation conditions for the supplementary firing canbe obtained with a combination of control as function of residual oxygenconcentration of the flue gases and of load of supplementary firing.

To optimize the efficiency the additional ambient air flow, and/oroxygen enriched airflow, and/or oxygen flow is preheated by low-gradeheat from a water steam cycle of the combined cycle power plant, and/orthe CO₂ capture system, and/or the flue gases.

Besides the method, a corresponding combined cycle power plant (CCPP) isalso part of the invention.

The CCPP comprises at least one gas turbine, one HRSG, one steamturbine, CO₂ capture system and a supplementary firing. Further, itcomprises one recirculation line and one flue gas line to the CO₂capture system.

According to one embodiment a low excess air supplementary firing isprovided in the HRSG of the combined cycle power plant.

In a further embodiment ambient air, and/or oxygen enriched air, and/oroxygen supply lines to the low excess supplementary firing is provided.

Additionally, an oxygen enrichment plant and/or an air separation unitcan be provided.

Further, at least one oxygen measurement or CO₂ measurement device canbe installed to measure the oxygen concentration or CO₂ concentration ofthe inlet gases of the compressor inlet gas and/or to measure theresidual oxygen concentration of the hot flue gases of the gas turbineand/or to measure the residual oxygen concentration of the flue gasesfrom the HRSG.

In addition to compensating power losses due to the CO₂ capture, thesupplementary firing can also be used to increase the plant flexibilityand to provide power to compensate the influence of variations in theambient conditions or to cover periods of peak power demand.

Typically, the recirculated flue gas has to be further cooled after theHRSG by a re-cooler before mixing it with ambient air for reintroductioninto the compressor of the gas turbine. In one embodiment the controlbody for controlling the recirculation rate is installed downstream ofthis re-cooler to reduce thermal load on this control body.

DETAILED DESCRIPTION

A power plant for execution of the proposed method includes aconventional CCPP, equipment for flue gas recirculation, a supplementaryfiring 10, plus a CO₂ capture system 18.

A typical arrangement with post combustion capture, flue gasrecirculation, and supplementary firing 10 is shown in FIG. 1. A gasturbine 6, which drives a first generator 25, is supplied withcompressor inlet gas 3, and fuel 5. The compressor inlet gas 3 is amixture of ambient air 2, and a first partial flow 21 of the flue gases,which is recirculated via a flue gas recirculation line. The inlet gasis compressed in the compressor 1. The compressed gas is used forcombustion of fuel 5 in a combustor 4, and pressurized hot gasses expandin a turbine 7. Its main outputs are electric power, and hot flue gasses8.

The gas turbine's hot flue gasses 8 pass through a HRSG 9, whichgenerates steam 30 for a steam turbine 13. In the HRSG 9 or the flue gasduct from the gas turbine 6 to the HRSG 9 supplementary firing 10 isintegrated. The supplementary firing is supplied with fuel gas 12 andambient air/oxygen 11.

The steam turbine 13 either is arranged in a single shaft configurationwith the gas turbine 6 and the first generator 25, or is arranged in amulti shaft configuration to drive a second generator 26. Further, steamis extracted from the steam turbine 13 and supplied via a steam line 15to a CO₂ capture system 18. The steam is returned to the steam cycle asa condensate via a return line 17 and is reintroduced into the steamcycle. The steam cycle is simplified and shown schematically withoutdifferent steam pressure levels, feed water pumps, etc., as these arenot subject of the invention.

A first partial flow 21 of the flue gases 19 from the HRSG 9 isrecirculated to the inlet of the compressor 1 of the gas turbine 6 whereit is mixed with ambient air 2. The first partial flow 21 is cooled inthe recirculation flue gas cooler 27 before mixing with the ambient air2.

A second partial flow 20 of the flue gases 19 from the HRSG 9 isdirected to the CO₂ capture system 18 by a damper 29.

A CO₂ capture system 18 typically consists of a CO₂ absorption unit, inwhich CO₂ is removed from the flue gas by an absorbent, and aregeneration unit, in which the CO₂ is released from the absorbent.Depending on the temperature of the second partial flow 20 of the fluegases, and the operating temperature range of the CO₂ absorption unit, aflue gas cooler 23 might also be required.

The CO₂ depleted flue gas 22 is released from the CO₂ capture system 18to a stack 32. In case the CO₂ capture system 18 is not operating,operating at part load, and to increase operational flexibility, theflue gases from the HRSG can be bypassed or partly bypassed via the fluegas bypass 24.

In normal operation the captured CO₂ 31 will be compressed in a CO₂compressor and the compressed CO₂ will be forwarded for storage orfurther treatment.

Measurement devices to measure the oxygen concentration and/or CO₂concentration are proposed in order to better control the residualoxygen concentration. For example, an inlet air CO₂ and/or O₂measurement device 36 can be applied for better control of inlet gascomposition for the gas turbine 6. For the control of the gas turbine'sflue gas composition a gas turbine flue gas CO₂ and/or O₂ measurementdevice 37 can for example be applied. To control the gas composition ofthe HRSG flue gas 19 a HRSG flue gas CO₂ and/or O₂ measurement device 38can for example be applied.

An example of a supplementary firing 10 for burning fuel gas 12 withambient air at low excess air ratio and with oxygen/oxygen enriched air11 in an HRSG 9 is shown in FIG. 2. In the shown example burner boxes 28for supplementary firing are arranged traversal, spaced apart in arraysin a cross section of the HRSG inlet 33 or inside the HRSG. Gas turbineflue gas 8 passes past the burner boxes 28 through the passages betweenthe boxes while the flame of the supplementary firing is stabilized inthem. Additional ambient air or oxygen 11 as well as fuel gas 12 aresupplied to the burner boxes and injected via the fuel gas injectionorifices 34 and the oxidizer injection orifices 35. Typically, oxygen isnot injected directly into burner boxes 28 but diluted with some carriergas like ambient air or recirculated flue gas before it comes intocontact with the fuel gas 12.

In a conventional CCPP with HRSG and supplementary firing the oxygenconcentration of the flue gases of the gas turbine 8 is not controlledand independent of the operation of supplementary firing. Thesupplementary firing typically is simply switched on, after the gasturbine reaches base load and operated independently of the gas turbine8. Base load is typically the operating condition with the lowestresidual oxygen concentration in the flue gases. The oxygenconcentration stays practically constant at this level and only slightchanges due to changes in the ambient conditions occur. However, thisapproach is not feasible with flue gas recirculation and minimizedresidual oxygen concentration in the hot flue gases from the gas turbine8, as conventional supplementary firing does not work properly underthese conditions.

In a first approach to maximize the CO₂ concentration of the flue gases19 from the HRSG 9 with supplementary firing, the residual oxygenconcentration after gas turbine GT_(O2) is controlled as a function ofthe relative load of the supplementary firing as shown in FIG. 3. It isnormalized with the minimum residual oxygen concentration of the fluegas from the gas turbine 8, which would be reached if the gas turbine 6were operated at the recirculation limit of the gas turbines. Foroperation of the supplementary firing the residual oxygen concentrationafter gas turbine GT_(O2) is higher than the minimum residual oxygenconcentration of the flue gas required for the gas turbine operation.Therefore the recirculation rate is restricted to allow supplementaryfiring.

In this case, no additional ambient air flow, and/or oxygen enriched airflow, and/or oxygen flow 11 is supplied to the supplementary firing 10.The amount of residual oxygen content and concentration required toassure stable, complete combustion with low CO and unburned hydrocarbonemissions depends on the temperature level and amount of fuel gas, whichneeds to react. At low relative load of the supplementary firing 10, thetemperature is low and a relatively high oxygen concentration isrequired to assure complete combustion. This leads to a high residualoxygen concentration after the supplementary firing SF_(O2). Withincreasing load, the flame temperature increases and the required oxygenconcentration drops until it reaches a minimum. For high relative loadof the supplementary firing 10 the required oxygen concentrationincreases again and is proportional to the injected fuel gas flow.Depending on the design of the supplementary firing, the requiredresidual oxygen concentration varies as a function of load. For example,a required oxygen concentration, which is proportional to the load, ispossible. Further, the load range might be restricted to higher loads,e.g. 40% to 100% load. In any case, in order to maximize the resultingCO₂ after supplementary firing, a variation of the residual oxygenconcentration of the flue gases from the gas turbine (GT) 8 is needed.This increases the complexity of the control integration, and can leadto combustion instabilities in the GT. Further, it leads to variation inthe second partial flow 20 of the flue gases, which flows to the CO₂capture system 18, as a function of the relative load of thesupplementary firing. The required residual oxygen concentration for thesupplementary firing can limit the recirculation ration and result in anincreased maximum second partial flow 20.

In a proposed second approach, supplementary firing with additionalambient air, oxygen enriched air or oxygen flow F_(air) from an oxygenenrichment plant/air separation unit 40 is applied. As schematicallyshown in FIG. 4, the normalized residual oxygen concentration of the gasturbine flue gas GT_(O2) required for supplementary firing over relativeload of the supplementary firing SF_(load) can be kept constantindependently of relative load of the supplementary firing. Therefore nocomplex control interface or logic between the gas turbine andsupplementary firing is needed.

In this proposed second approach, the fuel gas is burned in thesupplementary firing burner with an additional ambient airflow, oxygenenriched airflow or oxygen flow F_(air). The supplementary firing burnercan thereby work independently from gas turbine flue gas oxygenconcentration and produces flue gas at low O₂ and high CO₂concentrations. With this method it can be assured that after mixing theflue gases of the supplementary firing with flue gases of the gasturbine flue, the CO₂ concentration in the resulting flue gas mixturewill not be or only very slightly diluted. Thus the flue gasrecirculation rate could and shall be designed at its maximum allowedvalue to keep the minimal oxygen concentration i.e. the highest CO₂concentration in the gas turbine flue gases while sending the minimumamount of flue gas from CCPP to the CO₂ capture plant.

Further, the normalized additional ambient air, oxygen enriched air oroxygen flow F_(air) required to assure stable and complete combustion isalso shown in FIG. 4. It is normalized with the additional ambient airor oxygen flow required at 100% load. At low relative load of thesupplementary firing 10, the temperature is low and a relatively highambient airflow, oxygen enriched airflow or oxygen flow F_(air) isrequired to assure complete combustion. It is typically well abovestoichiometric and results in high residual oxygen concentration SF_(O2)after the supplementary firing. With increasing load the flametemperature increases and the required additional ambient airflow,oxygen enriched airflow or oxygen flow F_(air) only increases at a lowrate. The fuel specific additional ambient airflow, oxygen enrichedairflow or oxygen flow F_(air) can be reduced. Ideally almoststoichiometric combustion can be realized. For high relative load of thesupplementary firing 10 the fuel specific additional ambient airflow,oxygen enriched airflow or oxygen flow F_(air) stays almost constant.The required additional ambient airflow, oxygen enriched airflow oroxygen flow F_(air) is mainly needed to assure a sufficient oxygenconcentration for complete combustion and increases at a higher rate,which is proportional to the injected fuel gas flow. Depending on thedesign of the supplementary firing this dependency of required residualoxygen concentration as a function of load varies. Further, the loadrange might be restricted to higher loads, e.g. 40% to 100% load.

The resulting normalized residual oxygen concentration aftersupplementary firing SF_(O2) is also shown in this Figure. It isnormalized with the oxygen concentration after supplementary firingSF_(O2) at 100% load. For this example it reaches a minimum at 100%load. At 100% load the combustion temperature is highest, whichfacilitates a fast complete combustion down to very low residual oxygenconcentration and corresponding high CO₂ concentration.

In general the CO₂ concentration is inversely proportional to theresidual oxygen concentration, and low oxygen concentration correspondsto a high CO₂ concentration.

The CO₂ and the residual oxygen concentration at different locations ofthe thermodynamic process of a CCPP can be determined using main processparameters. Based on the inlet mass flow, the recirculation rate, thefuel mass flows, mass flow of ambient airflow, oxygen enriched airflowor oxygen flow F_(air) injected, and the combustion efficiency, theoxygen concentration and CO₂ concentration in the inlet gas, after thegas turbine, and after the supplementary firing can be estimated. Theseestimated values are used in one embodiment of the invention.

Since the inlet mass flow of a gas turbine is difficult to measure onenormally has to rely on compressor characteristics to determine theinlet mass flow. Due to compressor ageing the real inlet mass flow candiffer from the value of the characteristics. Further, the fuel'sheating value depends on the fuel gas composition, which can change overtime. Therefore either additional measurements like on line fuel gasanalysis have to be applied or considerable uncertainties have to betaken into account. For practical reasons it is therefore often easierto measure the gas compositions directly. These measurements are part ofa further embodiment. Corresponding measurement devices were indicatedin FIG. 1.

Besides conventional gas chromatography there are several differentmethods, systems, and measurement devices to measure the oxygenconcentration and CO₂ concentration of the different gas streams. CO₂can for example easily be measured using Nondispersive Infrared (NDIR)CO₂ Sensors, or Chemical CO₂ Sensors. Oxygen concentration can, amongothers, be measured using zirconia, electrochemical or Galvanic,infrared, ultrasonic sensors, and laser technology. Fast online sensorscan be applied for optimized operation.

Exemplary embodiments described above and in the drawings disclose to aperson skilled in the art embodiments, which differ from the exemplaryembodiments and which are contained in the scope of the invention.

For example, blowers might be advantageous for first partial flow 21 ofthe flue gases, which is recirculation or for the second partial flow 20of the flue gases, which flows to the CO₂ capture system 18. Withoutblowers the pipes and equipment size needed to allow sufficient flowwith existing pressure differences might become prohibitive.

Further, when an additional ambient airflow, oxygen enriched airflow oroxygen flow F_(air) is used for the supplementary firing this flow canbe preheated by low grade heat from the water steam cycle, and/or theCO₂ capture system 18, and/or the flue gases by a preheater 39. Returncondensate from intermediate pressure feed water can for example beutilized for this.

Further, one could replace dampers or other control bodies, whichinherently lead to a pressure drop, by controlled blowers. These couldfor example be variable speed blowers or blowers with controllable bladeor guide vane angles.

LIST OF REFERENCE SYMBOLS

-   1 Compressor-   2 Ambient air-   3 Compressor inlet gas-   4 Combustor-   5 Fuel gas for GT-   6 Gas turbine (GT)-   7 Turbine-   8 Hot flue gas from gas turbine-   9 HRSG (heat recovery steam generator)-   10 Low excess air supplementary firing (SF)-   11 Ambient air, and/or oxygen enriched air, and/or oxygen-   12 Fuel gas for supplementary firing-   13 Steam turbine-   14 Condenser-   15 Steam extraction for CO₂ capture-   16 Feed water-   17 Condensate return line-   18 CO₂ capture system-   19 Flue gas from HRSG-   20 Second partial flow (Flue gas CO₂ capture system)-   21 First partial flow (Flue gas recirculation)-   22 CO₂ depleted flue gas-   23 Flue gas cooler-   24 Flue gas bypass to stack-   25 First generator-   26 Second generator-   27 Recirculation flue gas cooler-   28 Burner box-   29 Damper-   30 Steam-   31 Captured CO₂-   32 Stack-   33 Cross section of HRSG inlet-   34 Fuel gas injection orifices-   35 Oxidizer injection orifices-   36 Inlet air CO₂ and/or O₂ measurement devices-   37 Gas turbine flue gas CO₂ and/or O₂ measurement devices-   38 HRSG flue gas CO₂ and/or O₂ measurement devices-   39 Preheater-   40 Oxygen enrichment plant/air separation unit-   CCPP Combined cycle power plant-   SF_(load) Relative load of supplementary firing (SF)-   GT_(O2) Normalized residual oxygen concentration after GT-   SF_(O2) Normalized residual oxygen concentration after SF-   F_(air) Normalized supplementary air/oxygen enriched air/oxygen flow

What is claimed is:
 1. A method for operating a combined cycle powerplant comprising at least one gas turbine (6), having a compressor (1),a combustor (4) and a turbine (7), a heat recovery steam generator(HSRG) (9), a steam turbine (13), a CO2 capture system (18), asupplementary firing (10), which is integrated into the heat recoverysteam generator (HSRG) (9) or installed as a duct firing (10) in theflue duct from the gas turbine to the heat recovery steam generator(HSRG) (9), and a flue gas recirculation line, the method comprising:mixing ambient air (2) and the first partial (21) flow of the flue gases(19); compressing the mixture of ambient air (2) and first partial flow(21); combustion fuel (5) in the combustor 4; expanding the pressurizedhot combustion gasses in a turbine (7); passing the turbine's hot fluegases through a heat recovery steam generator (HSRG) (9), whichgenerates steam (30); splitting the flue gas of the gas turbine into atleast two partial flows downstream of the heat recovery steam generator(HSRG) (9); recirculating a first partial flow (21) of flue gases (19)from the HRSG (9) via the recirculation line to the compressor inlet;directing a second partial flow (20) of the flue gases (19) from theheat recovery steam generator (HSRG) (9) to the CO2 capture system (18);capturing CO2 from a second partial flow (20) of flue gases (19) fromthe HRSG (9); operating the supplementary firing (10) to increase thenet power output of the plant and to at least partly compensate thepower consumption of the CO2 capture system (18); wherein thesupplementary firing (10) comprises burner boxes (28) arrangedtraversal, spaced apart in arrays in a cross section of the HRSG inlet(33) or inside the HRSG, and gas turbine flue gas (8) passes past theburner boxes (28) through the passages between burner boxes (28) whilefuel and additional ambient air or oxygen enriched air or oxygen aresupplied to the burner boxes (28) and the flame of the supplementaryfiring is stabilized in the burner boxes (28).
 2. The method accordingto claim 1, wherein the first partial flow (21) is recirculated atrecirculation rate, which is controlled at a highest possiblerecirculation rate under the conditions at which stable completecombustion in the gas turbine (6) can be maintained and at which aresidual oxygen concentration after the gas turbine (GTO2) is sufficientto maintain stable complete combustion of the supplementary firing (10).3. The method according to claim 2, wherein a sufficient ambient airflow, and/or oxygen enriched air flow, and/or oxygen flow (11) isinjected into the supplementary firing (lo), such that the recirculationrate can be controlled independently of the oxygen concentrationrequired for stable complete combustion of the supplementary firing(10).
 4. The method according to claim 3, wherein the additional ambientair flow, and/or oxygen enriched air flow, and/or oxygen flow (11) is afunction of the recirculation rate.
 5. The method according to claim 3,wherein the additional ambient air flow, and or oxygen enriched airflow, and/or oxygen flow (11) is a function of the residual oxygenconcentration after the gas turbine (GTO2).
 6. The method according toclaim 1, wherein the additional ambient air flow, and or oxygen enrichedair flow, and/or oxygen flow (11) is a function of the supplementaryfiring load.
 7. The method according to claim 3, wherein the additionalambient air flow, and or oxygen enriched air flow, and/or oxygen flow(11) is a function of the recirculation rate and or a function of theresidual oxygen concentration after the gas turbine and or a function ofthe supplementary firing load.
 8. The method according to claim 1,wherein the additional ambient air flow, and or oxygen enriched airflow, and/or oxygen flow (11) is preheated by low grade heat from awater steam cycle of the combined cycle power plant, and or the CO2capture system (1 a), and/or the flue gases.
 9. The method according toclaim 1, wherein the supplementary firing (10) is operated to increasethe power output for power augmentation during peak demand and toincrease its operational flexibility.
 10. A combined cycle power plantcomprising at least one gas turbine (6), a compressor (1) forcompressing inlet gas (3), a combustor (4) for combustion of fuel (5) inwith the compressed gas, and a turbine (7) for expanding pressurized hotgases combustion gas, at least one heat recovery steam generator (9),downstream of the turbine at least one steam turbine (13) at least oneCO2 capture system (18), downstream of the heat recovery steam generator(HSRG) (9), and flue gas recirculation line from heat recovery steamgenerator (HSRG) (9) to a compressor inlet, wherein a low excess airsupplementary firing (10), which can be operated in a gas flow with lessthan 10% oxygen concentration with a stoichiometric ratio below 2, isintegrated into the heat recovery steam generator (HSRG) (9) orinstalled as a duct firing (10) in a flue duct from the gas turbine tothe heat recovery steam generator (HSRG) (9) is provided, wherein thesupplementary firing (10) comprises burner boxes (28), arrangedtraversal, spaced apart in arrays in a cross section of the HRSG inlet(33) or inside the HRSG, such that gas turbine flue gas (8) can passpast the burner boxes (28) through the passages between burner boxes(28), and wherein the burner boxes (28) have an u-shaped cross sectionwhich is open do a downstream direction and comprise a fuel gas supply(12) and additional ambient air or oxygen or oxygen enriched air supply(11) to the inside of the burner boxes (28) such that the supplementaryfiring is stabilized in the burner boxes (28).
 11. The combined cyclepower plant according to claim 10, wherein ambient air supply lines, andor oxygen enriched air supply lines, and/or oxygen supply lines to thelow excess air supplementary firing (10) are provided.
 12. The combinedcycle power plant according to claim 10, further comprising an oxygenenrichment plant and or an air separation unit.
 13. The combined cyclepower plant according to claim 10, wherein at least one oxygenmeasurement device is installed to measure oxygen concentrations ofinlet gases of a compressor inlet gas (2) and/or to measure a residualoxygen concentration of hot flue gases of a gas turbine (8) and/or tomeasure a residual oxygen concentration of flue gases (19) from the heatrecovery steam generator (9).
 14. The combined cycle power plantaccording to claim 10, wherein at least one CO2 measurement device isinstalled to measure a CO2 concentration of inlet gases of a compressorinlet gas (2) and/or to measure a CO2 concentration of hot flue gases ofa gas turbine (8) and/or to measure a CO2 concentration of flue gases(19) from the heat recovery steam generator (19).